1. Field of the Invention
The invention relates generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to drag bits with blade profiles providing inherent stability and mechanical lock.
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods.
In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a “drill string.” The bit is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of all cutting methods, thereby forming a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The drilling fluid is provided to cool the bit and to flush cuttings away from the cutting structure of the bit and upwardly into the annulus formed between the drill string and the borehole.
Many different types of drill bits have been developed and found useful in drilling such boreholes. Two predominate types of rock bits are roller cone bits and fixed cutter (or rotary drag) bits. Most fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades project radially outward from the bit body and form flow channels therebetween. In addition, the cutter elements are typically grouped and mounted on several blades in radially extending rows. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors such as the formation to be drilled.
The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials. In the typical fixed cutter bit, each cutter element comprises an elongate and generally cylindrical tungsten carbide support member which is received and secured in a pocket formed in the surface of one of the several blades. The cutter element typically includes a hard cutting layer of polycrystalline diamond (PD) or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. For convenience, as used herein, reference to “PDC bit” or “PDC cutter element” refers to a fixed cutter bit or cutter element employing a hard cutting layer of polycrystalline diamond or other superabrasive material.
Without regard to the type of bit, the cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed, in order to reach the targeted formation. This is the case because each time the bit is changed the entire drill string, which may be miles long, must be retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer and which are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit may be employed before it must be changed depends upon its rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP. Additionally, a desirable characteristic of the bit is that it be “stable” and resist vibration, the most severe type or mode of which is “whirl,” which is a term used to describe the phenomenon where a drill bit rotates at the bottom of the borehole about a rotational axis that is offset from the geometric center of the drill bit. Such whirling subjects the cutting elements on the bit to increased loading, which causes the premature wearing or destruction of the cutting elements and a loss of penetration rate. Thus, preventing bit vibration and maintaining stability of PDC bits has long been a desirable goal, but one which has not always been achieved. Bit vibration typically may occur in any type of formation, but is most detrimental in the harder formations.
In recent years, the PDC bit has become an industry standard for cutting formations of soft and medium hardnesses. However, as PDC bits are being developed for use in harder formations, bit stability is becoming an increasing challenge. As previously described, excessive bit vibration during drilling tends to dull the bit and/or may damage the bit to an extent that a premature trip of the drill string becomes necessary.
There have been a number of alternative designs proposed for PDC cutting structures that were meant to provide a PDC bit capable of drilling through a variety of formation hardnesses at effective ROP's and with acceptable bit life or durability. Unfortunately, many of the bit designs aimed at minimizing vibration require that drilling be conducted with an increased weight-on-bit (WOB) as compared with bits of earlier designs. For example, some bits have been designed with cutters mounted at less aggressive backrake angles such that they require increased WOB in order to penetrate the formation material to the desired extent. Drilling with an increased or heavy WOB has serious consequences and is generally avoided if possible. Increasing the WOB is accomplished by adding additional heavy drill collars to the drill string. This additional weight increases the stress and strain on all drill string components, causes stabilizers to wear more and to work less efficiently, and increases the hydraulic pressure drop in the drill string, requiring the use of higher capacity (and typically higher cost) pumps for circulating the drilling fluid. Compounding the problem still further, the increased WOB causes the bit to wear and become dull much more quickly than would otherwise occur. In order to postpone tripping the drill string, it is common practice to add further WOB and to continue drilling with the partially worn and dull bit. The relationship between bit wear and WOB is not linear, but is an exponential one, such that upon exceeding a particular WOB for a given bit, a very small increase in WOB will cause a tremendous increase in bit wear. Thus, adding more WOB so as to drill with a partially worn bit further escalates the wear on the bit and other drill string components.
Accordingly, there remains a need in the art for a fixed cutter bit capable of drilling effectively at economical ROP's and, ideally, to drill in formations having a hardness greater than that in which conventional PDC bits can be employed. More specifically, there is a need for a PDC bit which can drill in soft, medium, medium hard and even in some hard formations while maintaining an aggressive cutter profile so as to maintain acceptable ROP's for acceptable lengths of time and thereby lower the drilling costs presently experienced in the industry. Such a bit should also provide an increased measure of stability as wear occurs on the cutting structure of the bit so as to resist bit vibration. Ideally, the increased stability of the bit should be achieved without having to employ substantial additional WOB and suffering from the costly consequences which arise from drilling with such extra weight.